As the urgency for petroleum production increases, situations arise with increasing frequency where air (containing oxygen) comes in contact with normally anaerobic fluids. It has been observed for years that oil field fluids that contact air can become many times more corrosive and, independently, corrosion inhibitors are not as effective against corrosion of iron and ferrous base materials under these conditions. These conditions are frequently difficult to diagnose and even more difficult to control.
In pumped producing wells, faster pumping in combination with reduced fluid flow into the well bore results in the annular space between outer casing and the production tubing no longer being filled with liquid. Pressures inside this space can become negative so air can be pulled into the gas filled cavity. In this rather commonly existing situation air can readily migrate to fluids in the region of the downhole pump causing corrosion damage there. In addition, air is picked up by the pump and forced up the production tubing causing additional corrosion damage to that tubing as well as sucker rods in the case of rod pumped wells.
Other instances of air contact with oil field fluids can occur because of secondary or tertiary recovery operations to recover more petroleum from the petroleum bearing formations within the earth. One example is in situ combustion operations which require air to be pumped into oil-bearing formations; not all of the oxygen in this air is consumed in the combustion and the excess gives rise to severe corrosion. A more common practice is that of pumping water into the formation to increase flow into producing wells in that formation. Air can be initially dissolved in this water if it is from a source at or near the earth's surface. If this water is being separated from produced fluid, it can pick up air during holding and pumping operations. In either case, air in these fluids can cause bad corrosion in both surface and downhole equipment. This corrosion also has serious indirect consequences because solid corrosion products form and cause plugging of inline filters and even worse, can plug pores in the formation rock so the rate of water injection is diminished.
Before the discovery of the oxygen-sulfur phosphate corrosion inhibitors, the typical solution to the air-contact-corrosion problem in pumped oil wells was to locate and eliminate any possible leak into the negative-pressure annular cavity. This is very difficult to accomplish in many cases, impossible in some.
In many oil field operations, contact of fluids with air is inevitable; two examples are the previously mentioned in situ combustion recovery stimulation, and the drilling fluids used to drill into potential petroleum bearing formations. With secondary recovery waters, however, the general rules are: Keep the air from contacting the water in the first place if at all possible; and, use chemical or mechanical scavengers to remove the oxygen if it does enter. When the water source is brine associated with produced petroleum, blanketing of holding tanks and pumps with gas-containing-no-oxygen is required to prevent air (oxygen) contact. As oil fields produce less natural gas and purchased gas prices increase, this practice becomes much less attractive. Other blanketing methods have been tried but have not proven effective at preventing oxygen entry.
In the event a water source is used which already contains oxygen—such as water from rivers, lakes, or shallow wells—chemical or mechanical scavenging is sometimes practical. Chemical reducing agents can be used to remove oxygen. Conditions must be controlled, however, so that oxygen removal is complete yet little unreacted excess scavenger remains. Mechanical scavenging can be accomplished by vacuum de-aeration treatment or counter-current scrubbing with a non-oxygen-containing gas. These methods also call for close control and are never applied to smaller quantities of water for economic reasons. In total, there are many systems where a one step corrosion inhibitor would be preferred and more economical than separate steps of scavenging and then addition of a corrosion inhibitor effective only in the absence of oxygen.
Even when oxygen is not in the corrosion system, oilfield corrosion is associated with deposition conditions. Iron sulfide or other solid particles can deposit on the steel surface and prevent corrosion inhibitors from accessing the surface. In some cases, these deposits can act as harbors for anaerobic bacteria which can also become involved in the corrosion process. Sulfate-reducing bacteria even produce their own environment beneath a biofilm that is safe from turbulence and flow velocities. As the biofilm grows, it forms an exoskeleton, which provides for sessile bacteria growth. Hydrogen sulfide is produced by the bacteria's metabolic processes and is released to the protected environment where it reacts with dissolved iron from the corrosion process to form iron sulfide. This combines with polysaccharides and other related molecules to form the cell walls with dead bacteria to produce a semi-permeable matrix we know as biofilm. Within the pores of these layers, its sulfate-reducing bacteria (SRB) grow and produce highly localized concentrations of H2S, accelerating the corrosion process and causing severe pitting. As the biofilm increases in volume, the ability to reach the bacteria with normal biocide treatment is reduced. Larger doses of biocide and longer contact time then produce only marginal performance, at best. This biofilm limits access to the metal by the filming corrosion inhibitor and the corrosion inhibition is further compromised.
The presence of H2S and CO2 further enhances corrosion. Electrochemical polarization curves had been used to show the particular conditions responsible for ferrous metal corrosion when oxygen contacts both sour (H2S) and sweet (CO2) production fluids. A test method for sour corrosion is to suspend linear polarization probes in brine made up with ferric ions and sparged with hydrogen sulfide. After fully saturating with hydrogen sulfide, the sparge is changed to air at a low flow rate. This test duplicates the desired conditions in sour fluids because of the oxidizing power of ferric ions early in the test plus the further oxidizing power of oxygen from air later in the test. A test method for sweet fluids is to suspend linear polarization probes in a brine continuously sparged with a CO2/air mixed gas. Electrochemical polarization tests show that the particular gas ratio used gives a reasonable contribution of both CO2 and oxygen to the corrosion and inhibition mechanisms. Test results typically correlate with field experience for established inhibitors in both categories.
The ideal chemical treatment would keep the metal surfaces free of deposits and inhibit the metal from a corrosive environment. This approach would prevent corrosion by-products (oxides and sulfides) that form deposits and foul the system. Bacterial growth would be discouraged because bacteria could not find a holiday in the inhibitor film where they could adhere to the metal and find a safe place to multiply. The bacteria would remain as a sessile form and this would significantly reduce microbiologically induced corrosion. If bacteria were detected, an EPA registered biocide would effectively sterilize the system. Water quality could be improved, drag effect would be reduced and the need for biocide treatments would be significantly reduced. All of these factors translate into lower operating costs.
At least for the foregoing reasons, there exists a need for a composition and method of inhibiting corrosion of downhole equipment.